(713b) Enhancing Hydraulic Fracturing Productivity Via Model-Based Feedback Control

In hydraulic fracturing, the proppant-filled fracture length at the end of pumping strongly influences the fluid conductivity of natural oil and gas [1]. Therefore, it is very important to regulate proppant bank height and suspended proppant concentration across the fracture to increase the recovery of shale hydrocarbon [2, 3]. Currently, pumping schedule is designed offline and applied to a hydraulic fracturing process in an open-loop manner, which may lead to poor process performance if there are large disturbances and plant-model mismatch.

Motivated by these considerations, we focus on the development of a model predictive control framework for the design of pumping schedule to regulate the spatial variation of proppant concentration across the fracture at the end of pumping for conventional and unconventional reservoirs. In conventional oil reservoirs, high-viscosity fracturing fluids ensure that most of the proppant remains in suspension during the treatment and the closure process. Thus, it is sufficient to regulate the suspended proppant concentration along the fracture at the end of pumping. In unconventional reservoirs, however, predominantly low-viscosity (“slick-water”) fluids are used and the proppant settles quickly forming a proppant bank, which will continue to grow until it reaches the equilibrium height; a state when the rate of proppant washout on top of proppant banks due to the shear force is equal to the rate of bank formation via proppant settling. To this end, we initially focus on the development of a first-principle model of a hydraulic fracturing process to obtain fundamental understanding of the proppant bank formation mechanism and its relationship to manipulated input variables such as proppant concentration and flow rate of the injected fracturing fluids. The optimal fracture geometry is obtained by applying Unified Fracture Design for conventional reservoirs [6] and a section-based optimization method for unconventional reservoirs [7]. Next, high-fidelity simulation data has been used to construct a data-based linear approximate model to design a Kalman filter that estimates unmeasurable states. Lastly, a model-based feedback controller is developed to achieve the uniform proppant bank height and suspended proppant concentration along the fracture at the end of pumping for conventional and unconventional reservoirs by explicitly taking into account the desired fracture geometry, type of the fracturing fluid injected, total amount of injected proppant, actuator limitations, and safety considerations.

References:

[1] Yang, S., Siddhamshetty, P., Kwon, J.S. (2017), Optimal pumping schedule design to achieve a uniform proppant concentration level in hydraulic fracturing. Compt. Chem. Eng., 101, 138-147.

[2] Siddhamshetty, P., Yang, S., & Kwon, J. S. I. (2017). Modeling of hydraulic fracturing and designing of online pumping schedules to achieve uniform proppant concentration in conventional oil reservoirs. Computers & Chemical Engineering. URL: https://doi.org/10.1016/j.compchemeng.2017.10.032.

[3] Siddhamshetty, P., Kwon, J. S. I., Liu, S., & Valkó, P. P. (2017). Feedback control of proppant bank heights during hydraulic fracturing for enhanced productivity in shale formations. AIChE Journal, 64(05), 1638-1650.

[4] Gu, H., & Desroches, J. (2003, January). New pump schedule generator for hydraulic fracturing treatment design. SPE Latin American and Caribbean Petroleum Engineering Conference, Port-of-Spain, Trinidad and Tobago.

[5] Nolte, K. G. (1986). Determination of proppant and fluid schedules from fracturing-pressure decline. SPE Production Engineering, 1(04), 255-265.

[6] Economides, M.J., Oligney, R.E., Valko, P., 2002. Unified fracture design. Orsa Press.

[7] Liu, S., & ValkÓ, P. P. (2017). Optimization of spacing and penetration ratio for infinite conductivity fractures in unconventional reservoirs- A sectional based approach. Society of petroleum engineers (SPE-186107-PA).